1. Field of the Invention
This invention relates to the use of modified alkaline earth oxides and carbonates for the effective reduction of a pollutant from flue gas resulting from the combustion of fossil fuel.
2. Description of Related Art
Power plants combust fossil fuels in boilers to create steam which is in turn used to power turbine-generators that produce electricity. At this time nearly one half of the electricity generated in the U.S. results from the burning of coal. When fossil fuel is combusted in a boiler, the sulfur present in fossil fuel reacts with oxygen to form sulfur dioxide. A small percentage of the resultant sulfur dioxide further reacts with additional oxygen present in the flue gas of the boiler to form sulfur trioxide. The combustion of fossil fuel also results in the production of mercury and arsenic which have deleterious effects upon unit performance and environmental health.
Traditionally, it has been assumed that approximately one percent of the sulfur contained in fossil fuel exits the combustion chamber as sulfur trioxide. The sulfur trioxide will react with moisture in the flue gas to form vapor phase sulfuric acid that will condense in the lower temperature regions of the boiler, more specifically the air heater as well as equipment farther downstream. Sulfuric acid has been found to form at temperatures less than 500 F. In addition to the substantial increase in fouling and corrosion to the equipment, the sub-micron sulfuric acid mist that exits the boiler exists as a finely divided aerosol, which deflects sufficient light in the atmosphere so that a visible “blue plume” becomes observable.
The “blue plume” creates anxiety in the community because everybody is concerned about the effects of industrial pollution. This situation is exacerbated when the flue gas is passed through a wet flue gas desulfurization system where the gas temperature is rapidly quenched to a temperature below the acid dew point.
Sulfur trioxide is classified as a Toxic Release Inventory substance therefore annual emission quantities must be reported to the Environmental Protection Agency. It is also very likely that pending environmental regulations will require the capture of very fine particulate, commonly referred to as “pm 2.5” which includes all particulate matter as well as condensable materials that are less than 2.5 microns in size. Such classification includes sulfuric acid aerosol. Many new construction permits being issued by individual States include condensable materials in the allowable total particulate emissions.
As would be expected, as the sulfur content in the fuel increases, the amount of sulfur trioxide formed in the boiler increases. Fuels typically used for the production of steam range from less than one percent to in excess of four-percent sulfur. Combustion of these fuels will therefore theoretically produce sulfur trioxide concentrations of approximately 5 ppm to 30 ppm, based upon the assumed conversion rate of one percent. Because of the relatively small concentrations of sulfur trioxide, little effort had traditionally been made to either measure or control this emission except for units firing costly oil.
Oil used for steam generation is also typically high in vanadium which increases the oxidation of sulfur dioxide to sulfur trioxide. The final temperature exiting the boiler is controlled such that the gas temperature does not fall below the sulfuric acid dew point. Typical boiler exit temperatures, downstream of the airheater range from 280 F to 350 F. Reduction of sulfur trioxide therefore enables lower boiler exit temperatures thus improving the overall thermal efficiency of the unit. The more costly the fuel, the more significant it is to reduce sulfur trioxide and lower boiler temperature to create better efficiency.
Recently promulgated environmental regulations have required substantial reduction of nitrogen oxides from fossil fuel fired boilers. The preferred technology for high nitrogen oxide removal from fossil fuel fired boilers is selective catalytic reduction, commonly known as SCR. This technology generally entails the installation of an external chamber that is equipped with several layers of catalyst. Upstream of the catalyst, ammonia is injected and a chemical reaction occurs on the surface of the catalyst converting the nitrogen oxide and nitrogen dioxide to nitrogen and water. A side effect of this technology is that the catalyst also oxidizes additional sulfur dioxide to sulfur trioxide. The amount of oxidation is a function of many parameters including the chemical composition of the catalyst as well as factors such as flue gas flow rates, volume of catalyst, temperature, etc. The chemical activity of SCR catalyst is most reactive when initially installed, as it will deactivate with increased exposure time to the flue gas. The catalyst will generally oxidize anywhere from less than one percent to as much as three percent of the sulfur dioxide entering the reactor to sulfur trioxide.
With the increased use of SCR technology because of the recently promulgated environmental regulations, an observable increase in the amount of sulfuric acid plume has become evident. While historically few measurements have been made to monitor the amount of sulfur trioxide produced, the application of SCR technology has resulted in such action. Not only have anticipated oxidation rates been observed across the SCR catalyst, it has also been confirmed that the assumed boiler conversion rate of one percent can be as much as 50 to 100 percent lower than actual sulfur trioxide concentrations.
A number of utility companies have been sited by the EPA for violation of opacity limits after the SCR systems have been placed in service. Current regulations require the operation of the SCR systems only during the “Ozone Season” which is defined as May 1 through September 30 of each year while many of the proposed future environmental regulations will require 12-month operation. Once year round operation of the SCR begins, the corrosion and opacity problems will increase proportionally.
In addition to increased sulfur trioxide emissions, a small amount of ammonia passes through the SCR reactor without reacting with the nitrogen compounds. This un-reacted ammonia, commonly referred to as “ammonia slip” is typically anticipated to be less than 2 ppm for typical coal fired applications; although concentrations as high as 10 ppm have been recorded. The ammonia slip readily reacts with sulfur trioxide to form ammonium bisulfate, when an excess of sulfur trioxide exists, that accumulates on the airheater surfaces. As a result of this fouling, the heat transfer efficiency deteriorates thus increasing the cost of power production.
At the same time the pressure differential across the airheater increases; often, to the extent that the boiler load must be reduced. If the situation is allowed to persist, the unit must reduce load or be shut down to clean the airheater. All of these phenomena result in significant added cost to the utility operator and reduce unit reliability.
Further, many utilities have also elected to “co-fire” petroleum coke which results in even higher levels of oxidation. This occurs because the petroleum coke, which can have sulfur content ranging from 4 to 7 weight percent sulfur, also can contain between 1000 and 3000 ppm vanadium, which is a very strong oxidant. Field measurements have recorded sulfur trioxide levels as high as 80 ppm when co-firing petroleum coke. This practice is currently gaining wide acceptance because of economic considerations.
Because of the situation described above, a concerted effort has been made by many parties to develop technologies to reduce sulfur trioxide. One of the most comprehensive efforts taken in this regard has been funded by the United States Department of Energy. This ongoing program has examined the introduction of a number of materials into utility boilers at various locations. This work has included various forms of several alkali's including limestone, lime and magnesium oxide or hydroxide.
Limestone injection into the boiler, while quite effective at removing sulfur trioxide and the least costly additive on a unit basis, was quickly discarded as a viable technology because of the very high dosage rates required. The required high dosage rates are in the range of a stoichiometric ratio of about 40. These high dosage rates of limestone demonstrated excellent sulfur trioxide capture; however it also introduced sufficient calcium to affect boiler eutectics such that slagging occurred.
Regrettably, while offering the lowest alkali unit cost and the simplest form of introduction, placement on the coal belt, this alternative has been deemed unacceptable because of the slagging. The need for such high dosage rates results from the sintering of the calcium carbonate at the very high temperatures in the flame region of the boiler which are generally in the 2500–3000 F range. The sintering is often referred to “dead burning.”
Other alkalis tested include various forms of magnesium, calcium and sodium. Magnesium may be added as magnesium oxide or magnesium hydroxide, the latter typically introduced as a slurry while the oxide form is added as a dry powder. Calcium hydroxide has been tested as both a dry powder and as a slurry. Irrespective of the chemical form in which these products are added, perhaps the most limiting factor is the ability to achieve adequate contact with the sulfur trioxide.
The cross sectional areas of large boilers can exceed 2000 square feet. Injection of a dry powder in the upper region of a boiler, where lower temperatures are more favorable for alkaline injection, would provide very poor flue gas/additive contact thus reducing the capture efficiency. While these products are capable of producing acceptable results with respect to sulfur trioxide capture, they require an elaborate and costly injection system and the unit cost per ton of available alkali is significantly higher than limestone. Further, injection into the furnace is subject to wide variability in flue gas flow rates as a function of unit load. The ideal injection point at 100 percent load may be poorest at a reduced unit load.
For the optimum system using magnesium, calcium or sodium it is therefore necessary to have a detailed temperature profile for each boiler over the range of anticipated operating loads. Multiple injection points would be preferred to help offset this impact adding to the complexity and cost of such system.
Testing has also been performed with the introduction of various alkalie downstream of the SCR and upstream of the airheater and electrostatic precipitator, typically as an aqueous solution. Once again, lances or nozzles must be used to maximize contact with the pollutant.
Perhaps the most comprehensive research effort undertaken to investigate methods of reducing sulfur trioxide is the ongoing study being performed by the U.S. Department of Energy's National Energy Technology Laboratory. The semi-annual report titled “Sulfuric Acid Removal Process Evaluation: Short-Term Results”, dated Mar. 4, 2002, as well as follow-up reports, authored by Gary M. Blyth and Richard McMillan, of URS Group, the prime contractor for this effort, discusses short term test results for several alkaline products. Of the many conclusions included in the report, the authors concluded that testing of the injection of dolomitc limestone through the burners should not be continued in the long term phase of the program. While the sulfur trioxide removal efficiencies with the dolomitic limestone were quite good, the amount required, stoichiometric ratios of approximately 40, and the adverse effects upon boiler operation because of the high dosage rate excluded this technology from further study.
While the study capture of sulfur trioxide is a very current effort, extensive development efforts have been performed in the past investigating furnace injection of limestone for sulfur dioxide control. While many of these efforts were exhaustive in nature, this technology has never gained commercial acceptance by the utility industry; primarily because of the low sulfur dioxide removal and the large amount of reagent required.
Landreth, et al, in his U.S. Pat. No. 5,246,364 teaches a method of injecting limestone through low NOx burners with mixing of the finely ground limestone with the tertiary air. While the Landreth technology is designed to capture a different pollutant, sulfur dioxide, as opposed to sulfur trioxide, his discussion of the impact of sintering of lime is germane to the teachings herein.
The Lavely U.S. Pat. No. 6,146,607 provides an excellent description of the calcinations on limestone. His teaches a method of injecting limestone into a furnace at a lower temperature range, collecting said resultant lime and utilizing it for sulfur dioxide capture after hydration.